Can Solar Fill the Hydropower Gap During California’s Drought?

• Although the scale of California's conventional hydropower remains much larger than that of solar power, solar's rapid growth provides a meaningful contribution to the grid.
• Solar power can work nearly anywhere, but installing it where it's actually sunny much of the time pays big dividends.

After reading a San Jose Mercury article with the unwieldy title, “Drought threatens California’s hydroelectricity supply, but solar makes up the gap” I was intrigued enough to do a little fact-checking on state-level  electricity statistics. The article quoted the head of the California Energy Commission, who implied that solar power additions were sufficient to make up for any shortfall in hydro, historically one of the state’s biggest energy sources. My initial skepticism about that claim turned out to be largely unfounded.

Solar has been growing rapidly, especially in California, but even with nearly 3,000 MW of photovoltaic (PV) and solar thermal generation in place, it’s still well short of the scale of California’s 10,000 MW of hydropower dams, especially when you consider that the latter aren’t constrained to operate only in daylight hours. However, I also know better than to respond to a claim like this without checking the data on how much energy these installations actually deliver.

My first look at the Energy Information Administration’s annual generation data seemed to confirm my suspicions. In 2012 California’s hydropower facilities produced 26.8 million megawatt-hours (MWh), while grid-connected solar generated just 1.4 million MWh. However, when I looked at more recent monthly data, the mismatch was much smaller, due to solar’s strong growth in the Golden State. For example, in September 2013 California solar power generated 435 MWh, or nearly 24% of hydro’s 1.8 million MWh.

The potential drought benefits of solar stand out even more sharply when we compare the growth in solar generation to the change in output from hydro. Last year solar electricity in the state increased by 2.4 million MWh, compared to 2012, while hydropower fell by 2.3 million MWh. That added solar power won’t provide grid operators the same flexibility as the lost hydropower, because of its cyclical nature, but it is clearly now growing at a rate and scale that makes it a serious contributor.

I’d be remiss if I didn’t point out that solar in California is still nowhere near the scale of the state’s biggest electricity source, natural gas generation, which in 2013 produced over 100 million MWh, or 57% of the state’s non-imported electricity supply. Gas is also filling much of the roughly 18 million MWh shortfall left by the early retirement of Southern California Edison’s San Onofre Nuclear Generating Station last summer, and if the state’s drought worsens, gas will be the main backup for further declines in hydropower.

Yet solar’s growing contribution to the state’s energy mix provides a clear demonstration that while generous state and federal policies can make installing PV economically attractive nearly anywhere, it’s abundant sunshine like California’s that makes it a useful energy source, especially when drought conditions reduce the output of other, water-dependent energy supplies.

A different version of this posting was previously published on Energy Trends Insider.

A Solar Car for the Masses?

• Ford is currently showing a concept car that addresses the shortcomings of solar-powered transportation in a clever way.

• If they can make it a cost-effective option, it would provide consumers a new kind of convenience, in contrast to the compromises inherent in most EVs.

It’s car show season again, with the annual crop of car-model launches like the new Corvette “supercar” and the Acura TLX prototype. However, my biggest regret in missing this year's Washington DC Auto Show was not seeing the Ford “C-MAX Solar Energi” concept, an unlikely marriage of electric vehicle (EV) and solar photovoltaic panels (PV). The car previously debuted at this year’s Consumer Electronics Show in Las Vegas.

This isn’t the first time a carmaker has put solar panels on the roof of a car, even if we exclude competitions like the Solar Car Challenge and other efforts to test how far or fast one-off solar vehicles designed by engineering students or enthusiasts could travel. However, I believe this is the first time an “OEM” has added solar panels to a production car for the purpose of providing a significant fraction of its motive power.
The biggest hurdles that any attempt to power a car with onboard solar panels must overcome are the low energy density of sunlight at the earth’s surface and the relatively low rate at which current solar panels can convert it into power. A typical EV requires 0.25-0.33 kilowatt-hours (kWh) of energy to travel one mile. 1.5 square meters of solar panel on the roof of a vehicle would receive on average only about 1.6 kWH per day in much of the US, assuming it was stationary and never parked under a roof or tree, and much less in winter. That’s only enough energy to travel 5 or 6 miles, or the equivalent of around 12 ounces of gasoline in a typical hybrid car. It's hard to fight physics.

The clever part of Ford’s solar design is its recognition that the rate of self-charging from the car’s rooftop wouldn’t be sufficient to liberate its owner from the gas pump without help in the form of an “off-vehicle solar concentrator.” This is essentially a glass carport that focuses the sun’s rays on the car’s PV roof and, according to the write-up in MIT’s Technology Review, works with the car’s software to move the car during the course of the day to keep the roof in the brightest area. That maximizes the amount of energy stored in the car’s battery, yielding enough for the daily needs of a fair percentage of drivers.

It’s not immediately obvious that combining two of the most expensive energy technologies of today — EV and PV — represents a good strategy for making them more competitive with the status quo, particularly given the likelihood of relatively stable gasoline prices for the next few years and the significant improvements being made in the fuel economy of conventional cars. 40 mpg highway is no longer considered remarkable. The ordinary hybrid version of the C-MAX is rated at 43 mpg combined city/highway, and the plug-in version on which the solar prototype is based is rated at 100 mpg-equivalent on electricity alone.

I have no idea what Ford would charge for the solar option should it eventually build the car, but it’s a good bet that it would be a significant multiple of the roughly $300 cost of the solar panels. Even without the Fresnel-lens carport, integrating PV into the car’s roof in a durable manner, together with the necessary changes to the car’s power management hardware and software, are unlikely to come cheap. Nor is it obvious that putting solar panels on a car’s roof is the best way to provide renewable electricity for vehicles. As Technology Review notes, Tesla is pursuing high-voltage (i.e., rapid) recharging facilities powered by stationary solar arrays, thus removing the constraint on effective PV area. It would be even simpler for many EV owners who want to avoid “exporting” their automobile emissions to fossil-fuel power plants to sign up for 100% renewable power from their local utility.

It’s no secret that EV sales have been disappointing, initially, for various reasons. 2013 sales figures for the US indicate that EVs, including plug-in hybrids like the non-solar C-MAX Energi, accounted for just under 100,000 new vehicles in 2013, or 0.6% of the US car market, compared to nearly 500,000 hybrids, or just over 3% of total sales of 15.5 million. If the US Congress eventually pursues tax reform along the lines suggested by recently retired Senate Finance Committee chair Max Baucus (D-MT), then the federal EV tax credit of up to $7,500 per car, which has helped push EV sales to current levels, would be in jeopardy. Carmakers should be thinking seriously about the long-term value proposition for EVs on their own merits.

The C-MAX Solar looks like a step in that direction. Once technology-hungry early adopters and the greenest consumers have been satisfied, the mass market will be seeking cars that compete on mainstream measures of convenience, cost and performance. In that light, even a Tesla that can be recharged to half its battery capacity in around 20 minutes via the company’s network of Superchargers falls short, compared to a gasoline car that can be refueled in under 3 minutes. No recharger on earth can deliver energy to a car at the effective rate of a gas pump, without dramatic changes in battery technology.

Yet the C-MAX Solar can do something that no other type of car can: make its own fuel, in a car that can also be refueled conventionally at any gas station, anywhere. That could provide a unique selling point, enhancing the convenience of cars in a totally new way, rather than requiring compromises on convenience as other plug-in EVs do.

I’ve long believed that the transition from fossil fuels to low-emission energy technologies has been hobbled by its dependence on government subsidies and would accelerate when those technologies can outperform on measures of “better, faster, cheaper.” Ford’s solar prototype must still demonstrate that it can become a real production car, rather just than a car show concept. If it does, it could help make EVs attractive to average consumers without requiring thousands of tax dollars in incentives. That could help create the basis for a truly sustainable transition to a new energy economy.

A different version of this posting was previously published on Energy Trends Insider.

US Oil Demand Returns to Growth

• Early estimates indicate that US oil demand grew by 2% last year, after several years of declining consumption.
• Although superficially consistent with recent GDP data, it's not yet clear whether this reflects a new trend or the results of non-recurring factors. 

After three straight years of declining oil consumption and a substantial net reduction since 2005, preliminary estimates suggest that US demand for petroleum and its products grew by 2% last year. In the estimation of the International Energy Agency (IEA) US demand growth in 2013 even outstripped that of China.  However, it strikes me as an exaggeration--or at least premature--to see signs, as a recent headline in the Financial Times suggested, that "America returns to gas-guzzling oil demand."  Is this a new trend, or just another blip?

The Energy Information Agency (EIA) of the US Department of Energy won't issue final figures on 2013 consumption for a few more weeks. In the interim, the American Petroleum Institute (API) released its estimates for December and the Fourth Quarter, showing a 5.8% year-on-year uptick for the month and a 4.6% increase for the quarter, compared to the final quarter of 2012. API's Chief Economist John Felmy cited "continued progress in domestic manufacturing as well as the broader economy."

The US economy has shown unexpected strength recently but continues to disappoint a sizable majority of Americans, based on recent polling. The economy added just under 200,000 jobs per month last year, while total employment remains  below its pre-recession peak. The government's first estimate at the end of January indicated that US gross domestic product grew by 3.2% in the fourth quarter of 2013, slower than the third quarter's relatively strong 4.1% pace. That puts full-year growth at 1.9%, or less than the 2.8% rate for the 2012 when US oil consumption shrank by 2% from the year before.

In any case, the  linkage between economic growth and oil demand has weakened over time, falling by more than 60% since the mid-1970s and by 20% just since 2000. In fact, following the peak in US oil demand in 2005, estimated oil and natural gas consumption per dollar of real GDP has declined by an average of 1.7% per year, only a little less than the average of post-recession US GDP growth. So annual efficiency gains come close to offsetting the impact of economic growth on US oil demand.

Some of this is the result of specific efficiency improvements, such as the 1.0 mile-per-gallon increase in the fuel economy of vehicles sold in 2013, compared to the previous year. Tracking data from the University of Michigan indicate a 16% improvement in the fuel economy of new cars since the 2008 model year. Of course it takes time for the impact of new higher-mpg vehicles to make a dent in the demand of a fleet of roughly 235 million cars and light trucks. That's even true of plug-in electric vehicles that use no liquid fuel at all. With cumulative US sales of around 160,000, EVs are displacing less than 5,000 barrels per day (bpd) of gasoline at this point, in a 9 million bpd market.

Because the primary use of oil in the US is in transportation, with less than 1% of it going to generate electricity, we should look at indicators of transportation activity for signals about changes in oil demand. The Federal Highway Administration's tally of US vehicle miles traveled (VMT) for 2013 was just 0.6% higher than 2012, through November, and remained more than 2% below its 2007 peak, only slightly more than a decade ago. If there's been a recent shift in driving habits, it's either well-hidden or involves a switch back to putting more miles on less-efficient vehicles--countering the anecdotal trend of the last few years. In the longer term, VMT growth will face headwinds from the changes in driver demographics I described last August.

In seeking explanations for last year's higher demand, we also can't ignore one-time factors like weather. Heating-degree-day data for the northeast during the fourth quarter shows a nearly 10% increase compared to 4Q2012. That indicates more days when the average temperature was farther below 65 F, and presumably more consumption of heating fuel as a result--a trend that seems to be continuing this quarter.

Scrutinizing EIA's detailed data on product supplied reveals that around two-thirds of the roughly 300,000 bpd annual increase in demand in 2013 (through October) was in the categories of liquefied petroleum gases (LPG) and low-sulfur distillate, both used for heating. For that matter, much of the growth in LPG demand is being met from the processing of shale gas, rather than crude oil refining, so its inclusion as part of "oil demand" is somewhat misleading. Nor do growing US net exports of refined products, at  around a million barrels per day last year according to API, have any bearing on this discussion, since they aren't included in the figures on which US consumption is gauged.

Another factor to consider when evaluating changes in oil demand is pricing. US retail gasoline prices averaged $0.11 per gallon less in 2013 than 2012, while retail diesel averaged around $0.05/gal. less. Those don't seem like big enough changes to affect demand, but the fourth quarter comparison is more dramatic, with gasoline and diesel $0.22 and $0.15/gal., respectively, less than a year earlier. That, together with a cooler fall, might help explain the fourth quarter bump in API's figures, which showed gasoline demand up by 3.7% year-on-year, and diesel up 5.3%.

Indications of a resurgence in US oil demand growth depend heavily on a single quarter's results, following a quarter of above-trend GDP growth--partially offset by efficiency gains that are expected to grow--and reinforced by cooler weather.  While I can easily imagine that a return to robust US economic growth, combined with persistently weaker fuel prices, could put US oil consumption on an ascending path again, I'd like to see a few more data points before discerning larger implications for global oil demand and prices.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Interpreting the State Department's Latest Assessment of the Keystone XL Pipeline

Earlier today, I participated in a webchat hosted by The Energy Collective on the subject of the emissions and market impact of the Keystone XL Pipeline (KXL). It was prompted by last week's release of the State Department's "Final Supplemental Environmental Impact Statement" (SEIS) on the project. I encourage you to view the Youtube video of the event, but I thought I should also share some of what I learned in the course of preparing for the webchat, along with a few thoughts there wasn't time to discuss online.

The full SEIS runs around 2,000 pages. I focused on the 38-page Executive Summary and referred to the relevant sections of the longer document when I needed more detail. In particular, I wanted to understand how the authors of the report had assessed the project's impact on greenhouse gas emissions (GHGs), including how they went about trying to gauge how the market would behave with and without the controversial northern leg of the pipeline, linking the Alberta oil sands developments to the main US oil storage and trading hub in Cushing, OK. (The southern segment of the pipeline, from Cushing to the Gulf Coast, is already in operation, because it didn't require a permit to cross an international border.)

President Obama's stated criterion--I still believe he will make the final call--is ensuring the project does not "significantly exacerbate the climate problem." In terms of emissions, the SEIS analysis shows a range of incremental lifecycle GHG impact of 1.3-27.4 million tons of CO2 equivalent per year. For a project this size, that falls below what I'd consider a reasonable threshold for "significantly". It's equivalent to 0.02-0.4% of total US emissions. On the low end that's on par with US emissions from making glass--not generally considered an important emitter.

Yet even if you don't accept State's conclusion that at expected oil prices over the next few decades the oil that would be carried by KXL would be produced with or without the pipeline, the total direct emissions of 147-168 million tons/yr would still only constitute 0.3% of global emissions of around 50 billion tons. As Jesse Jenkins of the Energy Collective pointed out in the webchat, the emissions of any project would look small compared to global emissions. That's precisely the point, when opponents have characterized them as "game over" for the world's climate.

The key to the conclusions in the SEIS is that these barrels will find a market somewhere, and in the process they will back out some other crude oil. As a result, they would have a minimal impact on the global oil price, and so would be unlikely to increase demand, which is what determines how much oil is refined globally. It's also the case that the alternative crude oils the incremental oil sands production would displace aren't much lower in lifecycle emissions, e.g., heavy Venezuelan or Middle East crudes.

Meanwhile, the report indicates that alternative dispositions would involve either longer or more energy-intensive transportation, including rail and/or tanker, entailing around a million tons per year in higher emissions, along with more spillage than expected from KXL. On that basis, it's hard to read this report as anything other than an endorsement of the view that the pipeline would have a minimal net impact, relative to the likely outcomes that would follow if it is not built.

One of the main points we didn't have much time to discuss in the webchat concerned the role of the SEIS in the decision that the administration must eventually make about the project's permit. I thought the most insightful recent comment on this came from President Obama's first Secretary of Energy, Dr. Steven Chu. He sees Keystone as a mainly a political choice. I agree. However, I wonder if the political considerations have started to shift.

Until recently, it seemed that the balance of political costs and benefits favored continuing to delay the decision as long as possible, by whatever means came to hand. That was certainly the case in 2012, with the White House at stake. An approval then might have pleased independent voters, but it would also have deterred an important segment of the President's political base. This year, with control of the US Senate--and thus the administration's agenda in its final two years--potentially up for grabs, the costs might be rising. At least four Democratic Senators in states that voted for Governor Romney in 2012 (Alaska, Arkansas, Louisiana and North Carolina) have made recent statements in support of the permit for KXL. An October surprise on Keystone might come too late to help them.

Nothing in the Supplemental Environmental Impact Report altered my previous view that President Obama should approve the permit for KXL. Yet because it was written after the Lac-Megantic rail disaster, I thought its figures on the potential for more rail accidents and fatalities if the pipeline isn't built added a compelling argument. Oil by rail is a new reality of the North American energy economy; KXL won't change that fact, one way or the other. However, the addition of up to 1,000 more rail cars of crude oil per day, passing through many more communities than the pipeline would, is a sobering reality to weigh against opposition that I heard another participant in today's webchat suggest was at least partly symbolic.

The Pros and Cons of Exporting US Crude Oil

• Calls for an end to the effective ban on exporting most crude oil produced in the US are based on a growing imbalance in domestic crude quality.
• At least recently, the ban has likely benefited refiners more than consumers. Assessing the impact of its repeal on energy security requires further study. 

Senator Lisa Murkowski (R-AK), the ranking member of the Senate Energy & Natural Resources Committee, issued a white paper earlier this month calling for an end to the current ban on US crude oil exports. Her characterization of existing regulations in this area as "antiquated" is spot on; the policy is a legacy of the 1970s Arab Oil Embargo. However, not everyone sees it the same way, either in Congress or the energy industry.

This isn't just a matter of politics, or of self-interest on the part of those benefiting from the current rules. Questions of economics and energy security must also be considered. The main reason these restrictions are still in place is that for much of the last three decades US oil production was declining. The main challenges for the US oil industry were slowing that decline while ensuring that US refineries were equipped to receive and process the increasingly heavy and "sour" (high sulfur) crudes available in the global market. The shale revolution has sharply reversed these trends in just a few years.

No one would suggest that the US has more oil than it needs. Despite the recent revival of production, the US still imported around 48% of its net crude oil requirements last year. Even when production reaches its previous high of 9.6 million barrels per day (MBD) as the Energy Information Agency now projects to occur by 2017, the country is still expected to import a net 38% of refinery inputs, or 25% of total liquid fuel supply. The US is a long way from becoming a net oil exporter.

The driving force behind the current interest in exporting US crude oil is quality, not quantity, coupled with logistics. If the shale deposits of North Dakota and Texas yielded oil of similar quality to what most US refineries have been configured to process optimally, exports would be unnecessary; US refiners would be willing to pay as much for the new production as any non-US buyer might. Instead, the new production is mainly what Senator Murkowski's report refers to as "LTO"--light tight oil. It's too good for the hardware in many US refineries to handle in large quantities, and for most that can process it, its better yield of transportation fuels doesn't justify as large a price premium as for international refineries with less complex equipment.

As a result, and with exports to most non-US destinations other than Canada or a few special exceptions effectively barred, US producers of LTO must discount it to sell it to domestic refiners. Based on recent oil prices and market differentials, producers might be able to earn as much as $5-10 per barrel more by exporting it. Meanwhile the refiners currently processing this oil are enjoying something of a buyer's market and are able to expand their margins. The export issue thus pits shale oil producers and large, integrated companies (those with both production and refining) such as ExxonMobil against independent refiners like Valero.

Producers are justified in claiming that these regulations penalize them and threaten their growth as available domestic refining capacity for LTO becomes saturated. Additional production is forced to compete mainly with other LTO production, rather than with imports and OPEC.

I believe producers are also largely correct that claims that crude exports would raise US refined product prices are mistaken. The US markets for gasoline, diesel fuel, jet fuel and other refined petroleum products have long been linked to global markets, with prices especially near the coasts generally moving in sync with global product prices, plus or minus freight costs. I participated in that trade myself in the 1980s and '90s. What's at stake here isn't so much pump prices for consumers as US refinery margins and utilization rates.

Petroleum product exports have become a major factor in US refining profitability, and refiners are reportedly investing and reconfiguring to enhance their export capabilities. This provides a hedge against tepid domestic demand. Nationally, refined products have become the largest US export sector and contributed to shrinking the US trade deficit to its lowest level in four years.  If prices for light tight oil rose to world levels US refineries might be unable to sustain their current export pace. It's up to policymakers to assess whether that risk is merely of concern to the shareholders of refining companies or a potential threat to US GDP and employment.

The quest to capture the "value added"--the difference between the value of manufactured products and raw materials--from petroleum production is not new. It helped motivate the creation of the integrated US oil companies more than a century ago and impelled national oil companies such as Saudi Aramco, Kuwait Petroleum Company, and Venezuela's PdVSA to purchase or buy into refineries in Europe, North America and Asia in the 1980s and '90s.

On the whole, OPEC's producers probably would have been better off investing in T-bills or the stock market, because the return on capital employed in refining has frequently averaged at or below the cost of capital over the last several decades. It's no accident most of the major oil companies have reduced their exposure to this sector. When today's US refiners argue that it is in the national interest to preserve the advantage that discounted LTO gives them they are swimming against the tide of oil industry history.

The energy security case for crude exports looks harder to make. An excellent article from the Associated Press quoted Michael Levi of the Council on Foreign Relations as saying, "It runs against the conventional wisdom about what oil security means. Something seems upside-down when we say energy security means producing oil and sending it somewhere else."  The argument hinges on whether allowing US crude exports would simultaneously promote more production and increase the pressure on global oil prices. That makes sense to me as a former crude oil and refined products trader, but it will be a harder sell to Senators, Members of Congress, and their constituencies back home.

The politics of exports may be easing somewhat, though, as a Senate vacancy in Montana could lead to a new Chair at Energy & Natural Resources who would be a natural partner for Senator Murkowski on this issue. (That shift may incidentally be part of a strategy to help Democrats retain control of the Senate.) Will that be enough to overcome election-year inertia and the populist arguments arrayed against it?

As for logistics, the administration could ease the pressure on producers without opening the export floodgates by exempting the oil output from the Bakken, Eagle Ford and other shale deposits from the Jones Act requirement to use only US-flag tankers between US ports. That could open up new domestic markets for today's light tight oil, while allowing Congress the time necessary to debate the complex and thorny export question.

Senator Murkowski wasn't alone in calling for an end to the oil export ban. In his annual State of American Energy speech presented the day as the Senator's remarks, Jack Gerard, CEO of the American Petroleum Institute, noted, "We should consider and review quickly the role of crude exports along with LNG exports and finished products exports, because of the advantages it creates for this country and job creation and in our balance of payments." In a similar address on Wednesday, the head of the US Chamber of Commerce stated, "I want to lift the ban. It's not going to happen overnight, but it's going to happen."  I'd wager he at least has the timing right.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Converting Coal to Synthetic Natural Gas in China

•  With so much attention focused on China's shale gas potential, its growing synthetic natural gas industry is a wild card.

• In light of China's severe air quality problems,  trading smog for higher CO2 emissions is an understandable choice, but one with global implications.

In its latest Medium-Term Coal Market Report the International Energy Agency (IEA) forecasts a slowing of coal demand growth but no retreat in its global use. That won’t surprise energy realists, but the item I wasn’t expecting was the reference in the IEA press release to growing efforts in China to convert coal into liquid fuels and especially synthetic natural gas (SNG).  It’s not hard to imagine China’s planners viewing SNG as a promising avenue for addressing the severe local air pollution in that country’s major cities, but the resulting increase in CO2 emissions could be substantial. It could also affect the economics of natural gas projects around the Pacific Rim.

Air quality in China’s cities has fallen to levels not seen in developed countries for many decades. There’s even a smartphone app to help residents and visitors avoid the worst exposures. Much of this pollution, in the form of oxides of sulfur and nitrogen and particulate matter, is the result of coal combustion in power plants. Although China is adding wind and solar power capacity at a rapid clip, after years of exporting most of their solar panel output, the scale of the country’s coal use doesn’t lend itself to easy or quick substitution by these renewables.

Natural gas offers a lower-emitting alternative to coal on a larger scale than renewables. Existing coal-fired power plants could be converted to run on gas or replaced with modern combined-cycle gas turbine power plants. Gas-fired power plants emit up to 99% fewer local, or “criteria” pollutants than coal plants, especially those with minimal exhaust scrubbing.

Unfortunately, China doesn’t have enough domestic natural gas to go around. Despite potentially world-class shale gas resources and the rapid growth of coal-bed methane and more conventional gas sources, natural gas supplies only 4% of China’s energy needs. Imported LNG can help fill the gap, but it isn’t cheap. What China has in abundance is coal. Converting some of it to SNG could boost China’s gas supply relatively quickly–perhaps faster than the country’s shale gas infrastructure and expertise can gear up.

SNG is hardly a new idea; the Great Plains Synfuels Plant has been producing it in North Dakota since the 1980s. When that facility was built, natural gas prices were volatile and rising, and greenhouse gas emissions appeared on no one’s radar. The process for making SNG from coal is straightforward, and its primary building block, the gasification unit, is off-the-shelf technology. I worked with this technology briefly in the 1980s, and my former employer, Texaco, licensed dozens of gasification units in China before the technology was eventually purchased by GE. Other vendors offer similar processes.

Gasifying coal adds a layer of complexity, compared to gasifying liquid hydrocarbons but this, too, has been demonstrated in commercial operations. Most of the output of the facilities Texaco sold to China was used to make chemicals, but the chemistry of turning syngas (hydrogen plus carbon monoxide) into pipeline-quality methane is no more challenging.

This effort is already under way in China. Last October Scientific American reported that the first of China’s SNG facilities had started shipping gas to customers, with four more plants in various stages of construction and another five approved earlier this year. The combined capacity of China’s nine identified SNG projects comes to around 3.5 billion cubic feet per day, or a bit more than the entire Barnett Shale near Dallas, Texas produced in 2007 as US shale gas production was ramping up. It’s also just over a quarter of China’s total natural gas consumption in 2012, including imported LNG.

To put that in perspective, if that quantity of SNG were converted to electricity in efficient combined cycle plants their output would be roughly double that of China’s 75,000 MW of installed wind turbines in 2012, when wind generated around 2% of the country’s electricity.

The appeal of converting millions of tons a year of dirty coal into clean-burning natural gas, in facilities located far from China’s population centers, is clear. This strategy even has some similarities to one pursued by southern California’s utilities, which for years imported power from the big coal-fired plants at Four Corners.  For that matter, the gasification process has some key advantages over the standard coal power plant technologies in the ease with which criteria pollutants can be addressed. Generating power from coal-based SNG might actually reduce total criteria pollutants, rather than just relocating them.

However, wherever these plants are built they would add around 500 million metric tons per year of CO2, or around 5% of China’s 2012 emissions, a figure that dwarfs even the most pessimistic estimates of the emissions consequences of building the Keystone XL pipeline. That’s because the lifecycle emissions for SNG-generated power have been estimated at seven times those from natural gas, and 36-82% higher than simply burning the coal for power generation.

What could possibly lead China’s government to pursue such an option, in spite of widespread concerns about climate change and China’s own commitments to reduce the emissions intensity of its economy? Having lived in Los Angeles when it was still experiencing frequent first-stage smog alerts and occasional second-stage alerts, I have some sympathy for their problem. China’s air pollution causes even more serious health and economic impacts and has been blamed for over a million premature deaths each year. By comparison the consequences of greenhouse gas emissions are more indirect, remote and uncertain. Any rational system of governance would have to put a higher priority on air pollution at China’s current levels than on CO2 emissions.

It might even turn out to be a reasonable call on emissions, if China’s planners envision carbon capture and sequestration (CCS) becoming economical within the next decade. It’s much easier to capture high-purity, sequestration-ready CO2 from a gasifier than a pulverized coal power plant. (At one time I sold the 99% pure CO2 from the gasifier at what was then Texaco’s Los Angeles refinery to companies that produced food-grade dry ice.) It should also be much easier and cheaper to retrofit a gasifier for CCS than a power plant.

In an internal context the trade-off that China is choosing in converting coal into synthetic natural gas is understandable. However, that perspective is unlikely to be shared by other countries that won’t benefit from the resulting improvement in local air quality and view China’s rising CO2 emissions with alarm. I would be surprised if the emissions from SNG were factored into anyone’s projections, and nine SNG plants could be just the camel’s nose under the tent.

In an environment that the IEA has described as a potential Golden Age of Natural Gas, large-scale production of SNG could also constitute an unexpected wild card for energy markets. When added to China’s shale gas potential, it’s another trend for LNG developers and exporters in North America and elsewhere to monitor closely.

A different version of this posting was previously published on Energy Trends Insider.

Canada: From Energy Supplier to Competitor?

• In addition to its impact on global oil and natural gas pricing and trade, the shale revolution is altering the energy relationship between the US and Canada.
• This long-standing supplier/customer relationship is becoming more complex as producers in both countries seek new markets outside North America.

In remarks last month the Canadian Natural Resources Minister, Joe Oliver, suggested that with the continued growth of unconventional oil production in the US, "Our only customer will become a competitor." Considering plans for liquefied natural gas export facilities on both sides of the border, he might have included LNG in that comment, too. Let's take a look at the kind of competition he might have had in mind.

Canada has long been an important supplier of crude oil to US refineries, since at least the 1950s. For much of the 1980s and '90s it was in a virtual three-way tie with Mexico and Venezuela for the #2 spot on the list of top oil exporters to the US, behind Saudi Arabia. Since 2004 Canada has claimed first place on that list as its production expanded, while Mexican and Venezuelan output declined and some Saudi oil went to other markets. From 2010 to 2012 exports of Canadian crude oil to the US, including oil sands crude, increased by 23% to over 2.4 million barrels per day (bpd). This has provided Canada with a reliable outlet for its production and the US with additional supplies not exposed--except for price--to ongoing instability in the Middle East and other regions.

However, with or without the Keystone XL Pipeline, the competition to feed US refineries is becoming more intense.  Canada's growing crude exports, including significant quantities of heavy and/or sour crude oil, must displace similar crudes imported into the US from  Latin America and the Middle East without losing ground to the expanded light oil production from US shale plays such as the Bakken and Eagle Ford, and the otherwise mature Permian Basin of Texas and New Mexico. Each of these areas now yields a million bpd. These dynamics are compounded by 1970s-vintage US oil-export rules that keep domestic crude bottled up in the Gulf Coast and weaken the economics of oil production throughout much of North America. 

If it seems odd for a Canadian official to talk about competition within the US market in this way, consider that the main country exempted from current US oil export restrictions is Canada. US oil exports to eastern Canada by rail and by tanker have grown rapidly in the last two years and are likely to expand beyond the current 100,000 bpd level, if export license applications are any indication. US oil exports to Canada may be displacing non-North American crudes today, but they likely also have an adverse effect on the economics of projects intended to ship more western Canadian crude eastward. So Canada now understandably looks towards Asia, home to the world's fastest oil-demand growth, as the logical destination for at least some of its future oil production.

 Natural gas creates another, perhaps more plausible arena for export competition between Canada and the US. Canada envisions a resurgence in gas production similar to what the US has experienced, based on a combination of conventional gas discoveries, such as in the Mackenzie Delta of the Northwest Territories, as well as the shales of Alberta and British Columbia. It also stands to gain additional gas reserves if it is successful in its bid to claim more of the Arctic. As Canadian gas is displaced from its long-standing export market in the US by the shale boom in the lower-48, LNG exports from B.C. are looking more attractive. The province lists five projects in different stages of development and highlights B.C.'s advantageous shipping route to Asia.

Many more LNG export projects have been proposed for the US, with at least four having received approval to sell to countries with which the US does not have free-trade agreements. A number of these are based on existing, or at least previously permitted, LNG import facilities, giving developers a head-start on construction. The US also has a big edge in proved natural gas reserves and technically recoverable gas resources, including shale gas.

Despite these US advantages, aspiring Canadian LNG exporters won't have to contend with an enormous domestic market for their gas, in which many industries are competing to use more gas in power generation, chemicals and other manufacturing, and different paths for displacing oil from transportation, including CNG, LNG, methanol, ethanol or gas-to-liquids fuels. As a result, I suspect that a Canadian LNG plant could count on a more stable long-term cost of gas than one on the US Gulf Coast.

The protracted controversy over the Keystone XL Pipeline project has focused a great deal of public attention on a single aspect of our energy relationship with Canada, while obscuring other aspects that are beginning to shift. Adding a new competitive overlay to our long-standing energy supply chains could ultimately increase North American leverage on OPEC's pricing power, while helping to develop a deeper and more flexible global market for LNG, with resulting environmental benefits. While this might result in winners and losers at the project and company level, the overall effect should be positive for both countries.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Energy 2013: More Shifts Ahead?

• 2013 was an eventful year for energy, though perhaps with fewer earth-shaking implications for the future than in other recent years.
• Several developments concerning global oil production, when taken together, improved the odds of lower oil prices in the next several years.

Year-in-review posts have become standard fare for energy blogs; I've written my share in the past. However, while 2013 hardly lacked for interesting energy-related news and events to populate a top-ten list, most fell short of the potential to affect energy markets strongly for years to come.

For example, it is newsworthy that another year has passed without an indication of whether the White House will approve or reject the cross-border permit for the Keystone XL pipeline project. Yet the consequences of that decision are becoming less significant, at least in the reported view of Bakken shale pioneer Harold Hamm. That's due in large measure to the dramatic increase in the transportation of oil by rail, which should be on anyone's top-ten list. Nor is it clear that the EPA's proposal to scale back the Renewable Fuel Standard's (RFS) corn ethanol quota for 2014 will affect more than this year's fuel market, unlike pending Congressional legislation to reform the RFS.  California's adoption of an energy storage mandate for utilities is another notable event, but its long-term impact is contingent on the development of cost-effective storage technology and business models to enable much greater integration of renewable energy on the grid.

Instead of extending that list, I'd like to focus on three stories in which I see significant, related implications for oil markets. The first involves the temporary international agreement concerning Iran's pursuit of nuclear technology. Although relaxation of the sanctions limiting Iranian oil exports depends on a highly uncertain final agreement governing uranium enrichment, the  Arak reactor's plutonium potential, and a more intrusive inspections regime, the interim deal signals that around a million barrels per day of Iran's oil--and eventually more--could be back on the market in less than two years.

If that happens, it won't be because the Iranian government's repeated assurances of its aversion to nuclear weapons have suddenly become credible, but because most of the permanent members of the UN Security Council plus Germany--the "P5 + 1" negotiating with Iran--are tiring of the protracted confrontation and understandably have no appetite to address this in the same way that the collapsing UN sanctions regime for Iraq was resolved in 2003.

Next consider the stunning reversal of the Mexican government's 75-year-old nationalization of oil and gas. As a result of the reforms just enacted by their congress and ratified by a majority of Mexico's states, the state oil company Pemex will be run along more commercial lines, and foreign firms will be allowed to partner with Pemex in developing the country's large untapped hydrocarbon resources. If the terms prove attractive for international energy firms, the result will move North America even closer to net energy independence. Meanwhile the Transboundary Hydrocarbon Agreement between the US and Mexico that was just passed by the US Congress will simplify energy development that straddles the border.

Mexico's potential could be even more significant for oil markets than an unconstrained Iran. The former's production has declined by 24% since 2004--a loss of 900,000 bbl/day-- mainly due to limited reinvestment. Foreign investment can help to restore that output, but the upside potential is much bigger. Pemex has barely scratched the surface of its deepwater resources in the Gulf. Its proven and contingent reserves are estimated at 45 billion barrels, while US estimates put Mexico's shale oil, or "tight oil" resources at 13 billion barrels, slightly more than the country's proved conventional reserves. (Shale gas could exceed 500 trillion cubic feet.)

Mexico's oil output has grown dramatically before. In the decade following the Arab Oil Embargo of 1973 production increased from 500,000 bbl/day to around 3 million. A similar performance seems possible again from a higher starting point, but it's unlikely to happen overnight. As Dan Yergen pointed out in a recent Wall St. Journal op-ed, "exploration and development could take another five to 10 years" beyond the first bid rounds.

And that brings us to Saudi Arabia's options for dealing with a shifting market that will include projected US crude oil output of 9.6 million bbl/day by 2016, the recovery and growth of Iraqi production, possible exports from Canada to Asia, Mexico's potential, and the eventual return of full Iranian exports. Whether or not this wave of new or restored production will be sufficient to replace production declines elsewhere, it must undermine OPEC's control of pricing in this decade. In that light, it's hard to ignore reported indications that Saudi Arabia might abandon its role of swing producer, particularly when it comes to unilateral output cuts to balance new non-OPEC supplies.

Haven't we seen this movie before? After a dozen years of high prices and tight markets OPEC steadily lost market share in the 1980s as new fields in Alaska, Mexico and the North Sea came online. That trend culminated in Saudi Arabia's 1986 "netback pricing" decision, linking the price of its oil to the value of its customers' refined petroleum products. Following the price collapse that policy helped precipitate,  oil prices took 18 years to reach $30/bbl again, by which time the dollar had lost a third of its value.

I doubt we're in for anything that dramatic. Back then, most demand growth came from the developed countries of the OECD, rather than from the expanding middle classes of developing Asia and the Middle East itself. Moreover, today's new production has higher costs--up to $70-80 per barrel--ruling out a return to $20 oil. With many serious geopolitical risks still in play, an oil-price price correction or extended soft market seems likelier than another price collapse. In the meantime, if we're seeking $20 oil, we already have it in the form of US shale gas that averaged the equivalent of $21.64/bbl last year. And that's the early, odds-on favorite for the energy story of the decade.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

IEA Forecasts Sustained Energy Growth, But No "Era of Oil Abundance"

• The IEA's latest long-term forecasts highlights the growth of unconventional oil and gas, especially in North America, but does not see this leading to much lower oil prices.
• In their main scenario fossil fuels will still meet more than three-fourths of the world's energy needs by 2035, despite significant growth in renewable energy.

The International Energy Agency (IEA) released its latest World Energy Outlook (WEO) in November, looking twenty-plus years into our energy future. The trends it describes add nuance and detail to last year's projections, rather than upending them.  Among other things they advance the expected date of global oil production leadership by the US to 2015 but suggest these gains may be short-lived and will not lead to "cheap oil."  The IEA also envisions a reshuffling of the traditional roles of energy importing, exporting and consuming countries, against a backdrop of steadily increasing energy-related greenhouse gas emissions.

As in previous years, the new WEO examines the full range of energy supply and demand, with a focus this time on the sources and uses of petroleum, and the emergence of Brazil as an oil and energy power. While recognizing that they might be underestimating the potential for technology or additional resource discoveries to sustain the growth of "light tight oil", or shale oil, which together with oil sands and gas liquids is a primary driver of oil supply growth today, the IEA forecasts it would peak by 2025.

That puts the burden for supporting oil demand growth and the replacement of supplies lost to natural decline after 2025 back onto the Middle East producers. So in the IEA's view, OPEC's loss of market power appears temporary. A corollary to this is that the agency does not anticipate a sustained drop in oil prices, but rather a gradual increase of about 16% by 2035. That's because the unconventional oil helping to drive current market shifts is still relatively high-cost, compared to the large conventional oil resources of the Middle East.

Although the IEA expects the global oil market to grow from its present level of around 90 million barrels per day (MBD) to 101 MBD in 2035, that change would be less than their forecasted equivalent global growth in gas, renewables or even coal. The concentration of oil demand in transport and petrochemicals would also increase, while other uses contract slightly. This is consistent with last year's observation that the center of the oil market is shifting towards Asia, since around one-third of the total anticipated growth in oil demand is for diesel to fuel goods deliveries in Asia.

The shift toward Asia applies to other forms of energy, as well, including natural gas and the expanded use of renewable energy.  This trend is already altering global energy trading patterns, and with the US becoming more energy self-sufficient  the IEA sees a new role for energy exports from Canada to supply Asia. That  includes both LNG and oil sands, which Fatih Birol, the IEA's chief economist, recently indicated the agency sees as only a minor, incremental threat to the climate compared to growing coal use.

An added nuance in this year's outlook is that the IEA now expects world-leading energy growth in China to be overtaken in a decade or so by faster growth in India, while rapidly growing consumption in the Middle East could result in that region posting the  second-highest growth in primary energy demand through 2035, especially for natural gas.

In the launch presentation in London Dr. Birol assessed the consequences of strong North American energy growth and shifting exports and imports for the prices that industries pay for energy. Because any exports of low-cost North American shale gas must be priced to cover the cost of liquefaction and long-haul freight, plus a margin, global natural gas prices should converge somewhat but still not equalize among the major consuming regions. As a result, the IEA expects US-based energy-intensive industries to have a persistent cost advantage in both gas and electricity, enabling them to increase their share of global markets. That has implications for employment and economic growth, while sustained energy price disparities should also drive energy efficiency improvements in response.

Another issue that received prominent attention at the launch was the always controversial matter of subsidies, for both conventional and renewable energy. The IEA estimated global fossil fuel subsidies at $544 billion 2012--mainly in developing countries and Middle East oil producers--resulting in "wasteful consumption" and fewer benefits for the poor than commonly claimed. And while supporting the use of subsidies to promote greater use of renewable energy, the agency's Executive Director, Maria van der Hoeven, made a particular point about the necessity for such subsidies to be carefully targeted and very responsive to changes in technology cost.

The IEA was founded in the aftermath of the 1973-74 Arab Oil Embargo and will celebrate its 40th anniversary next year. I couldn't help thinking about that as I reviewed the updated WTO materials. They're interesting as an annual update, but also in reflecting how the world of energy has changed since the oil shocks of the 1970s.

The rapid development of unconventional oil and gas that underpins the IEA's latest forecast would likely have amazed the industry veterans I met at the start of my career, but still fit within their worldview. I think they would have found the projected growth of renewable energy, supported by climate-change-inspired subsidies that surpassed $100 billion per year in 2012 more futuristic and surprising. Yet despite the anticipated expansion of renewable energy sources over the next 22 years, the IEA envisions the share of fossil fuels in the world's total energy supply only falling from 82% today to 76% in its main "New Policies" scenario.  That will seem overly cautious to many, but it underlines the challenges involved in changing such massive systems.

I'd like to wish my readers all the joys of the holiday season and a happy and prosperous New Year.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Is the Wind Energy Tax Credit About to Expire for Good?

• The expiration of the federal subsidy for wind power on 12/31/13 provides an opportunity to replace it with a smaller benefit, more focused on innovation.
• Comprehensive tax reform is the best way to approach this, including making tax incentives for energy consistent across the board.

With the end of the year fast approaching, the US wind power industry faces yet another scheduled expiration of federal tax credits for new wind turbines. The wind Production Tax Credit, or PTC, was due to expire at the end of 2012 but was extended for an additional year as part of last December’s “fiscal cliff” deal. With the PTC and other energy-related “tax expenditures” subject to Congressional negotiations on tax reform, it was looking like this might truly be its last hurrah in its current form, until Senator Baucus, Chairman of the Senate Finance Committee, released his draft proposal yesterday. Unfortunately, from what I have seen so far it falls short of sunsetting this overly generous subsidy and replacing it with a new policy emphasizing innovation.

In its 20-year history, minus a few year-long expirations in the past, the PTC has promoted tremendous growth in the US wind industry, from under 2,000 MW of installed wind capacity in 1992 to over 60,000 MW as of today. For most of its tenure, the PTC did exactly what it was intended to do: reward developers for generating increasing amounts of renewable electricity for the grid at a rate tied to inflation.

However, unlike the federal investment tax credit for solar power and some other renewables, the amount of the subsidy didn’t automatically decrease as the technology improved, with wind turbines growing steadily larger, more efficient, and cheaper to build. Instead, the PTC’s subsidy for wind power increased from 1.5 ¢ per kilowatt-hour (kWh) to its present level of around 2.3 ¢. That figure equates to up to $39 per oil-equivalent barrel, depending on which conversion from kWh to BTUs you choose.

It's also roughly one-third of today’s average US retail electricity price for industrial customers and exceeds most estimates of typical operating and maintenance costs for wind power. The latter point has serious implications for the impact of wind farms on other generators in a regional power grid.

If wind turbine installations continued at their remarkably depressed rate of just 64 MW in the first three quarters of this year, the cost of extending the current PTC for another four years and beyond, as Senator Baucus seems to be proposing, would be negligible. However, it’s evident from industry data that a major reason installations are so low in 2013 is that the uncertainty over last year’s scheduled expiration caused developers to accelerate projects into the record-setting fourth quarter of 2012. The American Wind Energy Association cites over 2,300 MW of new wind capacity under construction as of the end of September, while installations over the last three years averaged just under 8,400 MW annually.

At that rate, a one-year extension of the current PTC would add around $5 billion annually to the federal budget over the succeeding 10 years that each year's new wind farms would receive benefits. Congress’s Joint Committee on Taxation apparently came up with a slightly higher estimate of $6.1 billion for a one-year extension.

Before reflexively supporting or opposing another status quo PTC extension, we should ask what we’d be getting for that $5 or $6 billion a year. One of the commonest rationales I encounter justifying the continuation of the current PTC is that conventional energy still receives billions of dollars in subsidies each year. Without getting bogged down in arguments over the definition of a subsidy, or the real and imagined externalities associated with using fossil fuels, it is certainly true that the US oil and gas industry benefits from deductions and tax credits in the federal tax code to the tune of around $4.3 billion per year, based on figures in the latest White House budget.

If we compare these benefits on the basis of the energy production they yield, the PTC starts to look pretty expensive. For example, wind capacity additions in 2012 of over 13,100 MW increased wind generation by 20 billion kWh over the previous year. That’s the energy equivalent of about 140 billion cubic feet of natural gas in power generation, or 66,000 barrels per day of oil. (Although less than 1% of US oil consumption is used to generate electricity, oil is still an easily visualized common denominator.)

By comparison, US oil production expanded by 837,000 bbl/day, while natural gas production grew by the equivalent of another 606,000 bbl/day. So on this somewhat apples-to-oranges basis, oil and gas added more than 20 times as much new energy output to the US economy as wind power did, for roughly the same cost to the federal government.

Now, it’s true that domestic oil and gas both had banner years in 2012, in terms of growth, reversing longer-term decline trends in earlier years, but US wind had its biggest year ever last year. Another factor making this comparison more reasonable than it might otherwise seem is that these are all essentially mature technologies. Wind turbines are still improving, but these improvements are mainly incremental at this point. Nor do they or the billions in annual subsidies for wind address the single biggest obstacle to the wider adoption of wind energy, arising from its fundamental intermittency and disjunction with typical daily and seasonal electricity demand cycles.

When the PTC was first implemented in 1992, by its very existence it fostered innovation in a technology that was still in its infancy as a commercial means of generating meaningful quantities of electricity. That’s no longer the case. I’ve seen various ideas for reforming the PTC to make it more innovation-focused, but while these might be preferable to the status quo, they strike me as overly narrow. We don’t just need wind innovation, but energy innovation, and in fact innovation across the whole US economy if we want to remain globally competitive, and if we want to make more than incremental reductions in our greenhouse gas emissions.

It’s ironic in that context that the federal 20% research and development tax credit is also due to expire at the end of the year. If it came down to a choice between extending the R&D tax credit and extending the PTC, I’d hope that even the wind industry would opt for the R&D credit. That’s not entirely a false choice, considering the scale of ongoing federal deficits and debt, and the need for the government to borrow around 20% of what it spends.

Now is the ideal time to rethink the Production Tax Credit. Its expiration now wouldn’t be as abrupt as was foreseen at the end of 2011 or 2012, because last year’s extension redefined how projects qualify for the PTC. Any wind project that has either started significant work or spent 5% of its budget by year-end could still qualify for the current PTC in 2014. I have seen analysis suggesting a project begun now might even qualify after 2015, as long as work on it had been continuous.

That sets up a smoother transition, while Congress and the wind industry reevaluate what role, if any, specific wind-energy subsidies have in a national energy economy that looks very different than the one in which the PTC was first conceived in the 1990s. Making tax incentives more uniform across competing energy technologies, as Chairman Baucus's draft would do, is a good start, but instead of locking in a perpetual subsidy for current wind power technology at 50 times the rate of today's disputed oil & gas tax incentives, Congress should focus on making the tax incentives for all energy production consistent across the board, at levels that taxpayers can afford no matter how much these energy sources grow in the future.

A different version of this posting was previously published on Energy Trends Insider.

The LPG Echo of the Shale Gas Boom

• Increased US production of LPG and natural gas liquids is an outgrowth of the shale gas revolution and a key ingredient for translating its benefits into industrial growth.
• The infrastructure investments, export opportunities and price relationships for these liquids represent a microcosm of the similar issues for shale gas and LNG.

An article in the Wall St. Journal last month on the impact of a Midwest propane shortage on farmers trying to dry their corn harvest caught my attention. How could propane be in short supply, when US production is soaring due to shale gas? While it turns out that the shortfall in question was localized and temporary, it prompted me to take a closer look at LPG supply and demand than I have in many years. I found yet another market that is being transformed by the shale gas revolution.

Like most Americans--except for those in the roughly 5% of US homes heated with it-- I normally think about LPG only when I have to change the tank on my barbecue grill. That wasn't always the case; early in my career I traded LPGs for Texaco's west coast refining system. I'm happy to see that some of my former colleagues from that period are still involved and frequently quoted as experts on it. Although the LPG market is obscure to many, it represents a microcosm of the issues of reindustrialization and product exports arising from the recent turnaround in US energy output trends.

In order to follow these developments, we first need to clarify some confusingly similar acronyms, starting with LPG. Although often used synonymously with propane, it actually stands for "liquefied petroleum gas" and covers mainly propane and butane, though some in the industry include ethane in this category. The term reflects the oil refinery source of much of their supply, both historically and to an important extent today.  LPG overlaps with natural gas liquid (NGL)--ethane, propane, butane, isobutane and "natural gasoline"-- that has been separated from "wet" ( liquids-rich) natural gas during processing. NGLs are entirely distinct from the anagrammatical LNG, or liquefied natural gas, which consists mainly of methane that has been chilled until it becomes a liquid. By contrast, NGLs and LPG are typically stored at or near ambient temperature but under pressure to keep them in the liquid state.

LPG and NGLs make up a distinct segment of US and global energy markets, falling between the markets for natural gas and refined petroleum products. They are also linked to these larger markets, both logistically and economically. For example, gas marketers vary the amount of liquids they leave in "dry gas" to meet pipeline natural gas specifications based on price and other factors, and oil refiners blend varying quantities of butane into gasoline, depending on seasonal requirements. Propane and butane are mainly used as fuels, while ethane and isobutane are chiefly chemical feedstocks.

The development of shale gas in the US and Canada has affected the supply of NGLs and LPG in several important ways. First, starting around 2007 increasing shale gas output helped to halt and then reverse the decline in US natural gas production from which US NGLs are sourced. Then, following the financial crisis, diverging natural gas and crude oil/liquids prices pushed shale drillers toward the liquids-rich portions of shale basins like the Eagle Ford in Texas, in order to maximize their revenue. The resulting surge of US NGL production in late 2009 reinforced the decline of US LPG imports that began with the recession. According to US Energy Information Administration data, the US became a fairly consistent net exporter of LPG in 2011.

The current US LPG surplus is around 100,000 bbl/day, out of total production of around 2.7 million bbl/day. That surplus and its expected growth provides the basis for a number of announced LPG  export projects, as well as the anticipated development of new domestic chemical facilities such as ethylene crackers that would consume substantial portions of new supply, particularly of ethane.

The success of those projects depends on significant investments in new infrastructure, including gas processing, NGL fractionators to split the raw NGL into its components, and pipelines to deliver NGL to fractionators and LPG to markets. This is particularly true for the Marcellus and Utica shale gas in the Northeast, from which little or no ethane has been extracted due to limited local demand. Not only is that a missed manufacturing opportunity, but it constitutes a potential constraint on further liquids-rich gas development, since leaving too much ethane in the marketed gas would cause it to exceed pipeline BTU specifications.

In the meantime we're left with a situation that's analogous to the growth of tight oil production from the Bakken  shale. New sources of production have come on-stream faster than the infrastructure necessary to deliver them efficiently to where they can be processed or consumed. That puts a growing US surplus of propane and other NGLs in tension with tight regional markets for these fuels in the Midwest and Northeast, where residential propane prices are running well ahead of last year's at this time.  The resolution of this apparent paradox will depend on which infrastructure and demand projects are eventually completed, and how soon.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.